1. Field of Invention
The present invention relates to evaluation of subsurface earth formations to assess their composition and contents. More specifically, the present invention relates to accurate quantification of the effects of clay on data obtained from shaly sands.
2. Description of the Prior Art
It has long been the practice to evaluate subsurface formations, usually sands of interest, based on well logs obtained from wells in these formations. Parameters such as porosity and water saturation were determined. From these parameters, an assessment of the hydrocarbon content of the formation could be made.
Typically, the formation lithology included minerals which were termed clay or clay minerals. For a considerable time, shaly sand formation evaluation could not accurately quantify clay from standard well logs. Therefore, the effects of clay on porosity and resistivity logs were not accurately incorporated in shaly sands formation evaluation. Consequently, conventional formation evaluation of shaly sands has had some inaccuracy associated with its calculation of effective porosity and water saturations.
In logging analysis, formation evaluation of shaly-sands estimated total porosity, shale or clay volume, quartz or sand volume, effective porosity and water saturations of reservoir formations. Of course, hydrocarbon saturation was obtainable once water saturations could be estimated.
So far as is known, most prior art methods in shaly sand formation evaluation estimated shale abundance in the formation and incorporated the estimated shale-volume in calculating other formation attributes, such as effective-porosity. Examples of this were U.S. Pat. Nos. 4,403,290; 4,369,497 and 4,502,121. A very common practice in prior art methods in formation evaluation was to use gamma ray log to determine shale volume, as in U.S. Pat. No. 4,346,592. The highest readings of the gamma ray log (GR_MAX) were used to determine the 100% shale sections across a geological unit in the formation. Similarly, the lowest readings of the gamma ray log (GR_MIN) were used to determine the 0.0% shale sections across a geological unit in the formation. Afterwards, the shale at every depth point in such geological unit of the formation was quantified as Shale-Volume=(GR−GR_MIN)/(GR_MAX−GR_MIN), where GR is the gamma ray log reading at every depth point across the geological unit in the formation. In addition, other logs like density, neutron, spontaneous-potential and others were used in estimating shale-volume, as in U.S. Pat. Nos. 4,369,497 and 4,502,121.
Thus, quantifying pure clay abundance and incorporating its effects on porosity and water-saturation evaluation was not accurately accomplished in prior formation evaluation art. As has been discussed above, most prior art formation evaluation approaches quantified shale abundance and incorporated its effects in calculating other formation attributes. Occasionally, some prior formation evaluation methods, such as U.S. Pat. No. 4,346,592, used shale and clay terms as if they are equivalent when in fact they are not.
Typical formation shale is composed of clay, mica, feldspar, iron oxide, organics and other material. Sometimes, prior formation evaluation approaches like U.S. Pat. Nos. 4,531,188; 4,756,189; 4,502,121 and 4,369,497 attempted estimating clay from standard logs. Nonetheless, careful review of these methods revealed that one of two assumption or estimates usually was made. One was that the estimated clay was closer to shale than to pure clay, as in U.S. Pat. Nos. 4,531,188 and 4,756,189. The other was that the estimated clay was based on inaccurate definition of clay, as in U.S. Pat. Nos. 4,369,497 and 4,502,121, which assumed that Shale-Volume=Silt-Volume+Clay-Volume.
Generally, such prior formation evaluation approaches were associated with some inaccuracy in estimating effective porosity and water-saturation. Inaccuracy associated with effective porosity calculation in prior formation evaluation methods was due to the difficulty in obtaining accurate shale-volume, and due to the difficulty in incorporating accurate shale effects into effective porosity calculation.
Relations expressing total porosities, measured by density and neutron logs, in terms of effective porosity, shale volume, shale porosity, hydrocarbon saturation and hydrocarbon porosity were available in U.S. Pat. Nos. 4,369,497; 4,403,290 and 4,502,121. When hydrocarbon effects were negligible on density and neutron logs, the relationship between total porosity (from density and neutron logs), effective porosity, shale-porosity and shale-volume was as follows:Φtotal=Φeffective+Φshale·Volshale  (1)
Where Φshale was the shale pore-volume relative to the total shale volume and VOlshale was the volume of shale relative to the formation bulk volume.
Sometimes Φshale was approximated by Φtotal and Equation (1) reduced to the following:Φtotal=Φeffective+Φtotal·Volshale  (2)
Obtaining accurate effective-porosity from Equation (1) required accurate estimates for shale-volume and shale-porosity. This was, however, difficult during most times, especially in estimating an accurate measure of shale-porosity.
Estimating shale-porosity from porosity logs in the 100% shale sections was not accurate due to a number of reasons. First, the selection of 100% shale section could be wrong. Second, the porosity tools readings in such sections were mostly erroneous as they were affected by hydrogen index, shale composition and characteristics. Third, the so-called 100% shale section may not actually exist in the entire formation-interval to be evaluated. Fourth, the selection of 100% shale section was mostly subjective and the selected section might be different from one log analyst to another. Furthermore, shale-porosity in sections other than the 100% shale sections (sections where shale-volume is not 100%) was usually approximated by the same value estimated in the 100% shale sections. That introduced more inaccuracy in the shale porosity calculation. For these reasons, effective-porosity obtained from Equation (1) was mostly associated with inaccuracy.
Similarly, Equation (2) did not provide accurate effective-porosity, since the approximation of shale-porosity by total-porosity was inaccurate most of the time. Hence, effective-porosity, obtained using known methods, was associated with some amount of inaccuracy. The measures obtained were known to be inaccurate, but the extent of the inaccuracy could not be determined.
Inaccuracy associated with water saturation calculations, in prior methods of shaly sand formation evaluation, was due to number of possible reasons. The extra conductivity caused by the clay present in the shaly sand is not accounted for by Archie's equation. Thereby prior formation evaluation methods using Archie's equation could not account for the clay effects on saturation calculations, hence were mostly overestimating water saturations in shaly sands. Some prior methods used Waxman Smits and Dual Water to account for the extra conductivity caused by clay yet they could not have accurate measures for clay cation-exchange-capacity and clay-bound-water, which are required by Waxman Smits and Dual Water models. Thereby, such prior method could not obtain accurate relations for water saturations in shaly sands. Furthermore, most of the numerical techniques used by prior methods, to solve for water saturations from Waxman Smits or Dual Water equations, were not accurately converging.